The invention relates to a process for selective removal of sulfur compounds from gaseous mixtures containing H.sub.2 S, CO.sub.2 and significant quantities of COS.
For a variety of industrial applications, it is necessary or desirable to reduce the sulfur content of a gaseous mixture containing significant quantities of COS in addition to H.sub.2 S and CO.sub.2 to low levels prior to further processing and/or utilization of the gaseous mixture. For example, sour gas available from certain natural gas reservoirs is known to contain up to about 0.1% by volume (1000 ppm) COS in addition to substantial quantities of H.sub.2 S and CO.sub.2. Since the COS present in the sour gas makes up part of the total sulfur, substantial removal of same, in addition to the H.sub.2 S present, is necessary to meet many of the specifications for conventional end uses of such gas, e.g., residential heating and industrial uses. Further, in conventional partial combustion processes utilizing sour liquid hydrocarbon oils or sulfur-containing coals as the primary fuel source, a crude synthesis gas product is obtained which typically contains 100 to 500 ppm COS in addition to the H.sub.2 S and CO.sub.2 partial combustion by-products. In many cases this crude synthesis gas product is subject to further processing, e.g., contact with sulfur-sensitive CO-shift catalysts in hydrogen manufacture, or funneled to industrial and consumer end uses, e.g., as energy source in gas turbine generation of electricity or as a town gas for private consumption, which makes it desirable or even essential that the total sulfur content of the combustion gas be reduced to very low levels.
While reduction of the total sulfur content to low concentrations is required in most of these commercial applications, in a number of cases it is not necessary or desirable that carbon dioxide be removed from the gaseous mixture. For example, current pipeline specifications for natural gas permit relatively high concentrations of CO.sub.2 in the product gas as compared to total sulfur which is restricted to very low levels. Additionally, in cases where a Claus plant is utilized to recover the sulfur from the acidic components of the gaseous stream, it is advantageous to selectively remove the sulfur-containing acid gas components (usually in the form of H.sub.2 S) from the gaseous mixture while leaving a substantial portion of the CO.sub.2 in the treated gas stream, since CO.sub.2 merely acts as a diluent in the Claus reactant gases leading to larger and less economic processing facilities and less efficient conversions to elemental sulfur.
Processes for the removal of acidic gases, such as H.sub.2 S and CO.sub.2, for gaseous mixtures containing the same well known in the art. In general, these processes involve scrubbing the gaseous mixture with a liquid absorbent in an absorption zone whereby the acidic gases are removed from the gaseous mixture and a loaded absorbent stream is obtained which is passed to a regeneration zone where the absorbent is heated and/or stripped with solvent vapor, e.g., stream, resulting in the release of the acidic gases. The regenerated absorbent is returned into contact with the feed gas mixture in the absorption zone while the evolved acidic gases are passed to a cooler/condenser in which the solvent vapors are condensed and separated from the acidic gases.
In this same context, a number of processes utilizing liquid absorbents have been proposed to improve the selectivity for H.sub.2 S removal relative to CO.sub.2. Among the more attractive of such processes are those which employ aqueous alkanolamine absorbent solutions for selective removal of H.sub.2 S relative to the CO.sub.2. While these aqueous alkanolamine absorbent-based processes are generally adequate for selective removal of sulfur compounds relative to CO.sub.2, in cases where the chemically bound sulfur is present substantially in the form of H.sub.2 S, such processes become less effective and suffer from operational problems when substantial quantities of COS are present in the gaseous mixture to be treated. This is because COS exhibits absorption properties which closely resemble CO.sub.2 and most of these processes rely substantially, or at least in part, on the inherent difference in the rate of absorption of H.sub.2 S relative to CO.sub.2 in the absorption solution -- i.e., H.sub.2 S selectivity being improved by reducing the contact time between the absorbent and the H.sub.2 S and CO.sub.2 -containing gaseous mixture. In this regard see Canadian Pat. No. 947,045 and the Discussion of Prior Art in U.S. Pat. No. 3,266,866. Thus, when the absorption stage of the process is operated in a manner to achieve optimum selectivities for H.sub.2 S relative to CO.sub.2 by reliance on reduced contact times, very little of the COS will be absorbed by the alkanolamine absorbent and consequently will remain as a sulfur contaminant in the treated gas. It is known that COS can be removed by certain alkanolamine absorbent solutions including those which contain a tetramethylene sulfone, see for example, U.S. Pat. No. 3,347,621. However, in these instances the absorption stage of the process is operated in a manner such that all acidic components, including CO.sub.2 present, are absorbed. In any case, even if some intermediate set of processing conditions could be selected where COS would be removed without absorbing substantially all of the CO.sub.2 present in the gaseous mixture, the close similarity in the absorption properties of CO.sub.2 and COS would still result in more CO.sub.2 absorption than would occur when little or no COS is present in the gas mixture to be treated. Furthermore, at some stage of the absorption and/or regeneration process, it is anticipated that at least some of the COS would be hydrolyzed to CO.sub.2 and H.sub.2 S by the basic aqueous absorption solution; and consequently, the CO.sub.2 content of the absorbent and/or desorbed gases on regeneration would be increased. In practical terms this would mean that greater quantities of absorbent would have to be circulated through the processing scheme and the processing equipment sizing, e.g., gas-absorbent contactor and regeneration unit, would have to be larger since more total moles of absorbed acid gas would have to be handled. Further, in any case, the concentration of sulfur compounds in the recovered acid gases would always be lowered which could be especially critical in cases where the removed acid gases are passed to a Claus unit for recovery of the sulfur contained therein, since the economy and efficiency of the Claus unit is predicated to a substantial degree on the H.sub.2 S content of the feed gas.
Accordingly, it would be very advantageous if a process was available for reducing the total sulfur content of gaseous streams containing significant concentrations of COS, in addition to H.sub.2 S and CO.sub.2, down to low levels in which the selectivity for removal of sulfur compounds over CO.sub.2 is not sacrificed and the operational problems associated therewith are substantially overcome.